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Permalink Reply by Brian Powers on January 2, 2014 at 8:55am

Ruthie -

Wet Gas is simply dry gas (mostly methane) mixed with heavier hydrocarbon components like ethane, propane, butanes, pentanes, hexanes, heptanes, octanes, etc.

The prices for natural gas listed in the commodities market is typically for thousand cubic feet lots of dry gas (mcf), but the contracts are priced in million BTU lots (mmbtu), since it is a heat source that changes hands, not a volume per se. A typical mcf of dry gas contains roughly one million btu of energy. Wet gas can be much higher BTU; I've seen several analyses over 1400 btu/mcf. 

Wet gas has to be treated and conditioned to remove any free water or liquid hydrocarbons before it can be compressed and transported.

The gas is sampled at the wellhead into an evacuated stainless steel cylinder. In the lab, the sample is passed through a gas chromatograph that determines the overall heat content and the fractions of heavier hydrocarbons. From this analysis, process engineers can estimate the potential liquid yield through a fractionation or cracker plant.

I hope that this helps,

Brian 

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Permalink Reply by The Hiker on January 2, 2014 at 10:23am

Brian:   I assume that during the lab anlaysis, the amount of "condensate" is measured along with the gas and various NGL fractions in the gas chromatograph.   This information is then used to publish the IP of the well.   Does the % split between the components as measured initially remain "relatively" constant over the life of the well, or do some fractions deplete more quickly than others (ie,  condensate)?    Some wells initially reported an oil/condensate % from the IP test, but the Q3 numbers were woefully lacking this component.  Where did the oil go?  Not captured?   Ran out that quickly?  Shoddy test results?   Any light you could shed on this would be appreciated.  Thanks.

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Permalink Reply by Brian Powers on January 2, 2014 at 1:15pm

TH-

Any free liquids captured during the sampling process is included in the analysis. I've never seen a lab analysis of a gas sample used to determine IP- there are other factors/variables involved

I've not studied enough sample data trends during the productive life of a well to ascertain how the component split changes, though I can envision slight variation.

Condensate or oil in the liquid phase at reservoir conditions has to occupy a certain percentage of the pore space before it becomes mobile (the critical saturation point). If a well contacts a portion of the reservoir above the critical saturation point, the flush liquid production may indeed be higher for a period of time before depleting.

Brian

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Permalink Reply by Harry E. Rose on January 2, 2014 at 1:36pm

Brian, If they do not use lab tests to determine what is coming out of a well, what is used to measure the ingredients? Just interested. Harry

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Permalink Reply by Brian Powers on January 2, 2014 at 3:40pm

Harry -

A lab analysis is the only way that I know how to determine component percentage with certainty; anything else is mostly a guess.

As discussed in several posts in 2013, rough component composition can be estimated by the color of burning emitted by a well flare.

Well volumes are measured in a variety of ways; the most accurate in my view is orifice flow measurement, but it is worth remembering that the equations for orifice measurement were derived for fluids in single phase state (liquid or gas) and are much less accurate for mixed phase flow.

Brian 

 

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Permalink Reply by Harry E. Rose on January 2, 2014 at 5:22pm

Thanks Brian.

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